Fracturing fluids are today commonly used to fracture the rocks in order to enable or increase the fluids communication between the subterranean formation and the wells. The fluids present in the subterranean formation include water containing salts, gas, condensates and oil. Without the use of fracturing fluids, some rocks, which have a very low permeability, are unable to produce hydrocarbons like the ones associated with shale oil and shale gas. Some other rocks already produce hydrocarbons but it is desired to increase their output. To maintain the fractures opened, some solid particles, the “proppants”, are dispersed into the fluid above the surface and transported to the fractures during a pumping operation. The proppants are led and placed between the walls of the fractures.
To transport the proppants it is necessary that the fracturing fluid have a shear thinning behaviour: high viscosity at low shear so that the proppants do not settle in low turbulence areas of the injection system and in the subterranean formation and low viscosity at high shear to reduce the power necessary to pump the fracturing fluid.
By “shear thinning” is meant the diminution of the viscosity under the effect of an increase in the stress, the shear, and/or the deformation that are applied to the system under study.
Acid fracturing is a technique used to dissolve rocks in order to increase the permeability to hydrocarbons. In a first step a viscous water solution is injected into the subterranean formation to break the rocks, to create the desired fracture height, width, and length. Once the desired values of created fracture dimensions are achieved, the acid is pumped and fingers down the fracture to etch the walls of the fracture to create fracture conductivity. Then the fluids are pumped back to the surface with the same well and the pumping of the hydrocarbons begins. The acid is normally viscous or gelled or crosslinked or emulsified to maintain fracture width and minimize fluid leak off, with shear thinning behaviour. The most commonly used fluid in acid fracturing is 15% hydrochloric acid (HCl). To obtain more acid penetration and more etching, more concentrated HCl solution is sometimes used as the primary acid fluid.
If needed, formic acid (HCOOH) or acetic acid (CH3COOH) are used because the dissolving reaction between these acids and the rocks is more easily inhibited under high-temperature conditions. Hydrofluoric acid (HF) can also be used to etch subterranean sandstone formations. As the etching happens, the salts content of the water increases. To reduce the water leak off inside the rock porosity during etching, it is necessary that the viscosifying additive keeps its function while salt content increases.
Diverting fluids, conformance and permeability control fluids aim at decreasing the permeability of some parts of the subterranean formation. The formations possess sometimes valuable zones containing hydrocarbons but with different permeabilities or different water volume fractions. In such a case and when additional pressure is put into the subterranean formation with the injection of water to produce hydrocarbons, it happens sometimes that the water injected finds the fastest way to reach the producing wells, that is to say that it passes through zones with a high water volume fraction in the voids and/or with a high permeability, hence flowing around other hydrocarbon rich zones without pushing them towards the producing wells.
The conformance and permeability control fluids are injected in such high permeability and/or high water content zones to replace the fluids in place and reduce their permeability to water thanks to their high viscosity. High viscosity at low shear is necessary so that the slowly moving fluids coming from upstream cannot penetrate and low viscosity at high shear is necessary to reduce the power necessary to pump the conformance and permeability control fluids. The diverting fluids are injected in high permeability and/or high water content zones to replace the fluids in place and reduce their permeability to water thanks to their high viscosity. High viscosity at low shear is necessary so that the slowly moving fracturing fluids injected afterwards cannot penetrate and low viscosity at high shear is necessary to reduce the power necessary to pump the diverting fluid.
To control the production of sand coming from the subterranean formation with the hydrocarbons, one technique consists in placing a specific sized gravel pack in the annular space between the reservoir rock and the production assembly. The gravel acts as a filter allowing the formation fluids to flow from the formation to the production string while filtering out sand grains and other formation fines. To transport the gravel it is necessary that the sand control gravel pack placement fluid have a shear thinning behaviour: high viscosity at low shear so that the gravel does not settle in low turbulency areas of the injection system and low viscosity at high shear to reduce the power necessary to pump the placement fluid.
To control the viscosity of the abovementioned fluid, the prior art teaches that hydrophilic polymers are added to the water. Said polymers include polygalactomannan, guar or polymers derived from guar such as for example carboxymethylguar, hydroxyethylguar, hydroxypropylguar. Examples are given in the following patents: U.S. Pat. No. 5,305,832, U.S. Pat. No. 4,488,975, and U.S. Pat. No. 4,579,670.
However these polymers have drawbacks, e.g. the long time necessary for complete hydration in water, and the partial plugging of the created porosity because of their adsorption on the walls of the fractures. Other solutions exist to avoid these problems, using viscoelastic surfactants. Kefi et al. in “Expanding applications for viscoelastic surfactants”, Oilfield Review, Winter 2004/2005, pp 10-23, provides for an overview of the potential use of viscoelastic surfactants in the oil and gas industry and compares them with hydroxyethylcellulose for fracturing fluids. Viscoelastic fluids save energy because of the higher shear thinning ability. U.S. Pat. No. 6,637,517 and US2007/0213232 give examples of such viscoelastic fracturing fluids.
To help protection against chemical decomposition of these additives, known oxygen scavengers can be used such as sodium thiosulfate, methanol, thiourea, sodium thiosulfite. Other additives such as pH buffers, wetting agents, foamers, corrosion inhibitors, defoamers or antifoams, scale inhibitors, biocides, crosslinkers, gel breakers, non-emulsifiers, fluid loss control additives can be used. A gas can also be injected to produce gas bubbles inside the fracturing fluid such as nitrogen and carbon dioxide.
Clay stabilizers are used to prevent the swelling and/or dislodging of clays within the formation. The formation contains water which is equilibrated from the thermodynamic point of view with the rocks. Hence it has salts dissolved in it. The cations of these salts are equilibrated between the water phase and the clays. If the injected water has not enough cations dissolved in it, when it comes into contact with the rocks of the formation, the cations present inside the sheets of the clays diffuse into the injected water, leaving the sheets with a lower cationic charge. As a consequence the sheets which are negatively charged will repel each other and the clays are said to swell limiting the permeability which was created by the fractures.
Hence it is necessary to have enough salt inside the injected water to avoid this non equilibrated diffusion of cations between water and clays. What's more the dissolved salts act on the viscosity of the fracturing fluid.
The most common clay stabilizers are KCl, NaCl, quaternary ammonium salts such as NH4Cl, used at a dosage of from about 1% to about 5% by weight.
High volumes of water are necessary for hydraulically fracturing subterranean formations. Some areas where shale gas or oil is present have high constraints on the supply of water e.g. Texas, other places have farming lands or living places in the neighbourhood, making necessary a high quality for the treatment of the flow back fluids pumped back to the surface after the fracturing operations are run and before these waters are released, discharged. What's more these huge quantities of water are hauled. This adds impact on the environment through emissions for constructing the road network and hauling of water. It is thus highly desirable to reduce the consumption of water and increase the recycling of water for hydraulic fracturing operations. Recycling water means dealing with water containing high amounts of salts, such as NaCl, KCl, CaCl2, BaCl2, and the like.
US2009111716 teaches water soluble polymers, especially polyelectrolytes that are sensitive to salts in terms of rheology breakdown with salt increase and describes a solution to increase the salt resistance of water soluble polymers comprising a water soluble polymer, zwitterionic surfactants and inorganic salts and their use as hydraulic fracturing fluid. FIG. 8 of US2009111716 shows the impact of 5 wt % KCl on the viscosity of a 0.3% anionic guar water solution as a function of shear rate. The viscosity without KCl ranges from 0.4 Pa·s to 0.5 Pa·s and is equal to 0.09 Pa·s with a concentration of 5 wt % KCl at a shear rate of 0.1 s−1. The decrease is thus 75%. The addition of 2% of a given surfactant enables an increase of viscosity of 0.35 Pa·s at 0.1 s−1 in the presence of 5 wt % KCl. However this patent does not describe what is the sensitivity of the polymer/surfactant mixture as a function of KCl concentration and the addition of the surfactant is another step to prepare the fracturing fluid.
P. E. Dresel and A. W. Rose (Pennsylvania Geological Survey, Fourth Series, Harrisburg, (2010) pp. 11-12, http://www.marcellus.psu.edu/resources/PDFs/brines.pdf) teach that the formation waters present in oil and gas fields in Pennsylvania are difficult to analyze because sometimes the amount produced is very low so the data are not available or of bad quality.
P. E. Dresel and A. W. Rose (ibid.) also teach that the salts content in formation water can greatly vary in Pennsylvania from 7% w/v to 35% w/v and also in short distances of from 2 to 3 kilometers, for example for points 19 and 21 on the chart of page 11 for a sodium concentration ranging from 3 g/L to 17.4 g/L and for a calcium concentration ranging from 0.9 g/L to 6.1 g/L. If we consider that sodium and calcium are associated with chloride which is always the dominant anion, the variations in terms of NaCl and CaCl2 are respectively from 7.5 g/L to 44 g/L and from 2.5 g/L to 16.8 g/L. For these points 19 and 21, the calculated total amount of dissolved solids varies between 1% and 6.7%. It means that the choice of the fracturing fluid salt content is difficult and the common hydraulic fracturing fluid can be below the salinity of formation water expressed in terms of total dissolved solids.
On the one hand it is better not to be too low in salt content to avoid clay swelling anywhere in the formation accessible with the wells which reduces the permeability, and on the other hand having a high salt content means a reduced viscosity with polyelectrolytes and a reduced transport of proppants. In both cases the efficiency of the fracturing operation is reduced because of salts and a high quantity of water is necessary to fracture. It would be beneficial to work with a high salt content for the sake of avoiding clay swelling with shear thinning additives able to withstand these salt levels.
US2007213232 teaches the addition of an amine or alcohol to a viscoelastic gel in order to increase the critical temperature at which the viscosity starts to fall. This solution is said to be of value to get rid of the salt while maintaining the same viscosity. However FIG. 8 of US2007213232 shows the sensitivity of the claimed fluids to KCl in terms of viscosity at a shear rate of 1 s−1.
WO2012/085415 describes the preparation of specific filamentous particles by controlled radical emulsion polymerization of hydrophobic monomers, using as initiators living nitroxide-derived macroinitiators. The particles can be crosslinked. An other item described in US2007213232 is a direct technique for preparing filamentous particles that does not necessitate the use of an organic co-solvent. Filamentous polymeric aggregates are said to have an increasing attractiveness especially in biomedical applications as systems for administering drugs. These filamentous polymeric particles are exemplified with 35 g/L of NaCl in water. However no use in oil and gas extraction from subterranean reservoirs is described.
WO2012/085473 describes the increase of viscosity of water injected in a well for enhanced recovery of hydrocarbons with the help of a specific filamentous polymeric particles. The injected aqueous phase maintains the pressure in the reservoir and displaces the hydrocarbons toward the production wells. The particles can be crosslinked. The form and structure of the filamentous polymeric particles according to WO2012/085473 are maintained in a dispersed medium, independently of their concentration in the medium, of variations in its pH or its salinity.
The example given in FIG. 10 has a NaCl concentration of 35 g/L of water. Hence WO2012/085473 teaches that the polymer particle form and structure are not modified till a salinity of 35 g/L (3.5%) of NaCl. The mass fraction of particles is between 100 ppm and 10 000 ppm (that is a maximum of 1%). The term “brine” is employed but without definition so it is unknown what is the behaviour with a higher amount of salt or different salts and a higher amount of particles.
WO2012/085473 does not show rheology modification depending on the salt concentration because it teaches that the form and structure are not modified with salt. WO2012/085473 claims a method of enhanced hydrocarbon extraction. It means the rocks already produce some hydrocarbons and the technique claimed increases the output. The method of the above cited invention is implemented by means of a polymeric additive, wherein said additive is mixed with water or brine in a proportion of at least 500 ppm of additive and then this mixture is injected under pressure into the rock.
However it is not mentioned that the pressure is high enough to fracture the subterranean rocks and that proppants are used. Moreover the use of injection and production wells is mentioned, however not mentioned is the fact that each well can be alternatively used for injection of a water solution and production of hydrocarbons.
U.S. Pat. No. 8,347,960 describes an electro-coagulation treatment above the surface of the flow back water or source water coming from a hydraulic fracturing operation to remove the contaminants, re-use the water and to reduce the hauling of water. This process enables the recycling of water for following hydraulic fracturing operations. However it is said that chloride and sodium contaminants are not reduced by this process. The other contaminants are retrieved from the flow back water but must be disposed of.
There is therefore a need for a shear thinning hydraulic fracturing fluid containing proppants the viscosity of which at low shear rate (for example 0.1 s−1 to 1 s−1) decreases more slowly than the viscosity of existing fluids or even increases when its salt content increases up to 30% with the salts typically found in formation water, at constant concentration of shear thinning additive.
This lower sensitivity would enable an increase of the salt content like for example NaCl, KCl, CaCl2, BaCl2, and/or ammonium salts in the hydraulic fracturing fluid while keeping a shear thinning behaviour. Furthermore, the density of the fluid would be increased which would increase the pressure in the subterranean formation at constant pumping power and hence the fracturing efficiency.
What's more, as the formation water can have different salinities at different locations of a same subterranean reservoir and as the formation water mixes with the hydraulic fracturing fluid thereby modifying its salinity and as the salinity would have a lower impact on the new hydraulic fracturing fluid viscosity at low shear rates (for example 0.1-1 s−1) than for conventional fluids, then the viscosity of the new fracturing fluid would have a lower reduction and hence the ability of the new hydraulic fracturing fluid to transport proppants inside the fractures would be greater and the fractures would be kept open wider or this would reduce the amount of water and fracturing additives necessary to deliver the same amounts and flow rates (output) of hydrocarbons.
This lower sensitivity or reversed sensitivity (in the case of viscosity increase upon salt addition) would make it possible also to reuse the flow back water which is a mixture of hydraulic fracturing fluid and formation water for the following fracturing operations, that is as a true recycling operation:
1—for example starting from an amount of salt in the fracturing fluid close to the estimated formation water salt content which is usually high (above 5 wt %), the viscosity of the flow back fluid decreases essentially due to dilution of shear thinning additive. It is then necessary to add the lacking concentration of shear thinning additive. In the case of a hydraulic fracturing fluid of the prior art, as the viscosity is low at high salinity and because of dilution by formation water, the relative lacking concentration is higher than for the filamentous polymeric particles that have a lower sensitivity to salt.2—for example starting from an amount of salt in the fracturing fluid lower than the estimated formation water salt content, and using a shear thinning additive having an inverse sensitivity to salt, the viscosity of the flow back fluid will decrease due to dilution of the shear thinning additive. But this effect will be limited due to the increase in salt content coming from the formation water and which tends to increase the viscosity.
After having increased its viscosity by adding additives, the reuse of the flow back water, coming from the mixture of known hydraulic fracturing fluids or coming from the hydraulic fracturing fluid mixture which could solve the salinity issue described above, with formation water without separating contaminants such as salts would be beneficial from several points of view: less energy would be used and these contaminants would stay at the fracturing site or below, limiting the dissemination due to hauling.
In the case of diverting fluids, conformance or permeability control fluids, sand control gravel pack placement fluid, acid fracturing fluids, there is the same need for a shear thinning fluid (containing gravel in the case of sand control gravel pack placement fluid) the viscosity of which at low shear rate (0.1 s−1 to 1 s−1) decreases more slowly than the viscosity of existing fluids or even increases when its salt content increases up to 30% with the salts typically found in formation water, at constant concentration of the shear thinning additive.